Natural gas or gases associated to oil productions produced from geological reservoirs, or refinery acid gases often contain(s) acid contaminants, such as carbon dioxide and/or hydrogen sulfide and/or other sulfur contaminants, such as carbonyl sulfide, carbon disulfide and mercaptans. For most of the applications of these gas streams, the acid contaminants need to be removed, either partially or almost completely, depending on the application and the type of contaminant.
Methods to remove carbon dioxide and/or hydrogen sulfide and/or other sulfur contaminants from a hydrocarbon gas stream are known in the prior art.
One common approach to remove acid contaminants involves the use of solvents such as chemical solvent (amine-based solvent), hybrid solvent or physical solvent. These solvents have been largely disclosed in the art. However, if appreciable levels of sulfur compounds are present in the acid gas, the most common process to eliminate hydrogen sulfide is to convert said hydrogen sulfide into a non-hazardous by-product such as elemental sulfur. The Claus process is a known type of sulfur recovery process allowing the conversion of hydrogen sulfide into elemental sulfur, by sending it to a sulfur recovery unit (SRU).
In some embodiments, remaining H2S traces are captured in a Tail Gas Treatment Unit (TGTU), positioned at the outlet of the Claus unit to increase significantly sulfur recovery, and then be recycled into the Claus unit. The TGTU converts small amounts of sulfur compounds (<5%), which were not converted in the sulfur recovery unit (SRU), into hydrogen sulfide (H2S) and recycles it back to the SRU for additional processing. The TGTU is composed of at least four equipments: a hydrogenation reactor, a waste heat exchanger, a quench tower and an acid gas absorption column.
The SRU tail gas is heated and sent to the hydrogenation reactor where essentially all of the sulfur compounds are converted into H2S. The gas from the hydrogenation reactor is cooled in the waste heat exchanger and the quench tower. The cooled gas is then sent to the acid gas absorption column, where amine removes the H2S and some of the CO2 contained in the gas stream. The H2S and CO2 removed from the amine is cooled (and water removed) in the overhead condenser and recycled to the sulfur recovery unit for additional processing into sulfur. At the outlet of the TGTU, native CO2 is recovered. It is diluted by a large amount of nitrogen coming from the combustive agent used for Claus combustion. To recover a purified CO2 stream, CO2 capture technologies using solvent (for example an amine solvent, such as MethylEthanolAmine (MEA)) can be used. However, since the CO2 is diluted in a large volume of nitrogen, the amine-based CO2 capture unit requires large size equipments, thereby leading to huge CAPEX and OPEX.
Furthermore, an incinerator is generally connected at the outlet of the amine-based CO2 capture unit in order to incinerate the nitrogen, the hydrogen, the carbon monoxide and the remaining traces of sulfur contaminants.
At the outlet of the amine-based CO2 capture unit a purified stream of native CO2 is recovered, however this CO2 stream contains hydrogen sulfide in such quantities that do not meet certain specifications, and more particularly such purified CO2 cannot be used for enhanced oil recovery (EOR) applications.
Therefore, there is a need for a method that allows recovering high quality native CO2 from a hydrocarbon feed gas stream which contains acidic compounds, such as CO2, H2S and other sulfur contaminants, with better purity compared with the processes of the prior art.